Field
The present invention relates to measurement of the properties of reservoir fluids. More specifically, the present invention is related to downhole spectroscopic measurement of reservoir fluids using oil-water mixtures.
Description of Related Art
Hydrogen sulfide (H2S) can be present in subsurface hydrocarbon reservoirs. The presence of hydrogen sulfide is highly corrosive to casing, tubing, and other metallic and polymeric tools. This effect is considerably accelerated by low pH and the presence of carbon dioxide. Additionally, hydrogen sulfide is hazardous to humans even at small concentrations (for example, above 100 ppm). Thus, the measurement of the concentration of hydrogen sulfide in reservoir fluids has great value for oilfield companies because it can improve investment decisions and reduce potential health and safety hazards. For example, with knowledge of the concentration of hydrogen sulfide in the reservoir fluids, appropriate health and safety measures can be planned for the various stages of reservoir characterization and development (i.e., exploration, appraisal, development, production, and abandonment). In another example, special metals or process designs can be used that address the hydrogen sulfide concentration in the reservoir fluids. In yet another example, water or steam injection of a reservoir can promote the activity of bacteria that leads to the formation of hydrogen sulfide gas. The onset of such hydrogen sulfide formation conditions can be detected and mitigated.
At present, the measurement of the concentration of hydrogen sulfide in reservoir fluids is attained through analyzing samples captured through downhole fluid sampling tools (such as the Modular Dynamics Tester (MDT™) tool available from Schlumberger Technology Corporation of Sugar Land, Tex., USA). Such tools are typically capable of collecting samples in metal containers and maintaining them at reservoir pressure and temperature conditions. These samples are transported to a surface laboratory for fluid analysis typically involving spectroscopic and gas chromatographic analysis. Although the above technique is effective, the accuracy is somewhat compromised as it does not account for any scavenging that may take place on the metal surfaces of the sampling tool as well as any mud filtrate present in the sample container.
U.S. Pat. No. 7,025,138 discloses the use of metal coupons as a means of monitoring concentrations of hydrogen sulfide. The coupons are integrated into sampling tools and are exposed to downhole fluids. A reaction of a respective coupon with the downhole fluids causes a change in the coupon (such as a change in coloration) in the event that the concentration of hydrogen sulfide in the downhole fluid exceeds a predetermined threshold level. This technique is rather qualitative in nature in that it identifies the presence of hydrogen sulfide at a concentration over the threshold level, but does not provide a measure of the actual concentration of hydrogen sulfide. Moreover, the technique employs a reaction time in the range of two to six hours, and thus is not capable of hydrogen sulfide gas monitoring at different depths and sampling points during one trip within a wellbore.
U.S. Pat. No. 6,939,717 discloses several embodiments for the measurement of hydrogen sulfide in wellbore fluids. The first technique is based on a headspace measurement of hydrogen sulfide in the gas phase above the liquid sample, which is formed by reducing its hydrostatic pressure. The concentration of hydrogen sulfide in the original liquid hydrocarbon sample can be calculated from the measured gas phase concentration and knowledge of the Henry's law constant for the hydrocarbon sample. This measurement method can also be applied to the hydrogen sulfide content of formation water samples if the pH of the sample is either measured or fixed by a suitable buffer. The second technique is based on the measurement of the flux of hydrogen sulfide across a gas extraction membrane in contact with a flowing sample of reservoir fluid. Several methods are described to measure the flux of hydrogen sulfide across the extraction membrane. The first method uses a reduction-oxidation cell that oxidizes the hydrogen sulfide by converting ferricyanide to ferrocyanide ions and the measured reduction-oxidation current is directly proportional to the concentration of hydrogen sulphide in the reservoir fluid. The second method measures the methylene blue formed in an optical absorption cell by the reaction of the hydrogen sulfide diffused across the membrane with iron (III) ions and N,N-dimethyl-p-phenylenediamine in an acidic aqueous solution; the methylene formed is detected spectrophotometrically at a wavelength of 660 nm. The rate of change of absorbance at 660 nm is directly proportional to the concentration of hydrogen sulfide in the reservoir fluid sample. The effectiveness of the techniques of U.S. Pat. No. 6,939,717 are limited in harsh downhole conditions (for example, high pressure conditions (up to 15,000 psi) and high temperature conditions (up to 150° C.)) because the buffer compounds as well as reduction-oxidation compounds can destabilize and undergo side reactions at elevated temperatures.
International Patent Application Publication WO 2007/034131 employs an electrochemical sensor for measuring pH and hydrogen sulfide content of reservoir fluids, which in turn can be used for predicting mineral scale and for corrosion assessments. The sensor is applicable to downhole sampling tools. The effectiveness of this electrochemical sensor can be limited in harsh downhole conditions (for example, high pressure conditions (up to 15,000 psi) and high temperature conditions (up to 150° C.)) due to degradation of the sensor solution at elevated temperatures. Moreover, as the technique requires a porous membrane material to facilitate transfer of sulfide species into the aqueous mediator solution, the mechanical robustness and overall suitability for downhole deployment are limited.
A more recent study entitled “Accurate Measurement of the Hydrogen Sulfide Content in Formation Fluid Samples,” SPE 94707, 2005, reports successful detection and monitoring of hydrogen sulfide concentration through a systematic sampling analysis that involved the use of an optimized and modified formation tester (i.e. minimal hydrogen sulfide scavenging) and rapid analysis on the surface to drastically reduce any incident that can contribute to underestimating hydrogen sulfide levels. This technique requires testing times on the order of days to measure hydrogen sulfide concentration, and thus is not suitable for hydrogen sulfide gas monitoring at different depths and sampling points during one trip within a wellbore.